Expandable coating for solid particles and associated methods of use in subterranean treatments

ABSTRACT

A variety of methods and compositions are disclosed, including, in one embodiment, a method of treating a subterranean formation comprising: providing coated particles, wherein the coated particles comprise solid particles coated with an expandable coating; and introducing the coated particles into a permeable zone of the subterranean formation such that the coated particles form a barrier to fluid flow in the permeable zone. In another embodiment, a method of drilling a well bore may be provided, the method comprising: including coated particles in a drilling fluid, the coated particles comprising solid particles coated with an expandable coating; using a drill bit to enlarge the well bore; and circulating the drilling fluid past the drill bit.

CROSS-REFERENCE TO RELATED APPLICATIONS

The present invention is a divisional application of U.S. patentapplication Ser. No. 13/677,527, filed on Nov. 15, 2012, the entiredisclosure of which is incorporated herein by reference.

BACKGROUND

The present invention relates to subterranean treatments and, moreparticularly, in certain embodiments, to methods and compositions thatutilize solid particles having an expandable coating in subterraneantreatments.

In subterranean operations, there may be instances where it can bedesirable to limit or prevent the flow a fluid into or through aparticular portion of the subterranean formation or well bore. Forexample, it may be desirable to limit or prevent the loss of circulationof fluids, such as drilling fluids, into the subterranean formation.Such fluids may be lost into fractures induced by excess fluidpressures, into pre-existing fractures, or into large openings withstructural strength in the formation, among other locations. Thisproblem may be referred to as “lost circulation,” and the sections ofthe formation into which the drilling fluid may be lost may be referredto as “lost-circulation zones.” The loss of drilling fluids into theformation is undesirable, inter alia, because of the expense associatedwith the drilling fluid lost into the formation, loss of time,additional casing strings and, in extreme conditions, well abandonment.In addition to drilling fluids, problems with lost circulation may alsobe encountered with other fluids, for example, spacer fluids, completionfluids (e.g., completion brines), fracturing fluids, and cementcompositions that may be introduced into a well bore.

In other instances, it may be desirable to limit or prevent the flow ofwater, which may be undesirably produced in subterranean operations. Forexample, when hydrocarbons are produced from wells that penetratehydrocarbon-producing formations, water often accompanies thehydrocarbons, particularly as the wells mature over time. The water canbe the result of a water-producing zones communicating with thehydrocarbon-producing formations or zones by fractures,high-permeability streaks, and the like. Alternatively, the water can becaused by a variety of other occurrences which are well known in theart, including water coning, water cresting, bottom water, channeling atthe well bore, etc. The production of water adds undesired expense andcomplexity to the production of the hydrocarbons.

A number of different techniques have been developed to limit or preventfluid flow into or through a particular portion of the subterraneanformation or well bore, which may be useful in the prevention lostcirculation and/or control of the undesirable production of water. Insome instances, chemical systems have been used to limit or preventfluid flow. One type of chemical system that has been used is chemicalgels that resist the flow of injected fluids or the natural aqueousdrive fluid through high permeability channels and fractures. Thegeneral approach has been to inject a mixture of reagents, initially lowin viscosity, into a zone of the formation that has high permeability.After a sufficient time to allow the mixture to be pumped into thesubterranean formation or when exposed to the elevated temperature ofthe formation, the mixture of reagents then forms a gel to block fluidflow. In addition, chemical systems commonly referred to as “relativepermeability modifiers” have also been used to decrease the productionof water. One example of a commonly used relative permeability modifieris polyacrylamide. These methods typically work at the formation faceand/or well bore; however, in some instances formation damage may occur.

In addition to chemical systems, additional techniques that have beenused for lost circulation control involve the placement oflost-circulation materials into the lost circulation zone. Conventionallost-circulation materials may include fibrous, lamellated or granularmaterials. The lost-circulation materials may be placed into theformation, inter alia, as part of a drilling fluid or as a separatelost-circulation pill in an attempt to control and/or prevent lostcirculation. The lost-circulation materials typically form a seal in thelost-circulation zone (e.g., by packing off perforation tunnels, platingoff a formation surface, plating off a hole behind a slotted liner, orpacking along the surface of a hydraulic fracture) that prevents losscirculation of the drilling or other fluid into the formation. However,it is often desired to subsequently remove the lost-circulationmaterials to allow the maximum flow of produced fluids that comprisehydrocarbons from the subterranean zone to flow into the well bore.Subsequent operations necessary for removing such lost-circulationmaterials often entail considerable time and expense and addedcomplications.

SUMMARY

An embodiment of the present invention provides a method of treating asubterranean formation comprising: providing coated particles, whereinthe coated particles comprise solid particles coated with an expandablecoating; and introducing the coated particles into a subterraneanformation.

Another embodiment of the present invention provides a method ofdrilling a well bore comprising: including coated particles in adrilling fluid, the coated particles comprising solid particles coatedwith an expandable coating; using a drill bit to enlarge the well bore;and circulating the drilling fluid past the drill bit.

Another embodiment of the present invention provides a subterraneantreatment fluid comprising: a base fluid; and coated particles, whereinthe coated particles comprise solid particles coated with an expandablecoating.

The features and advantages of the present invention will be readilyapparent to those skilled in the art. While numerous changes may be madeby those skilled in the art, such changes are within the spirit of theinvention.

BRIEF DESCRIPTION OF THE DRAWINGS

These drawings illustrate certain aspects of some of the embodiments ofthe present invention, and should not be used to limit or define theinvention.

FIG. 1 illustrates an example embodiment of an uncoated solid particle.

FIG. 2 illustrates an example embodiment of a coated particle in anunexpanded configuration.

FIG. 3 illustrates an example embodiment of a coated particle in anexpanded configuration.

DESCRIPTION OF PREFERRED EMBODIMENTS

The present invention relates to subterranean treatments and, moreparticularly, in certain embodiments, to methods and compositions thatutilize solid particles having an expandable coating in subterraneantreatments. While the coated particles may be useful in a number ofdifferent applications, they may be particularly useful for controllingfluid flow in subterranean formations.

There may be several potential advantages to the methods andcompositions of the present invention, only some of which may be alludedto herein. One of the many potential advantages of the methods andcompositions of the present invention may be that the expandable coatingon the solid particles may expand, for example, when contacted by anactuating fluid such as oil or water in a subterranean formation,allowing the solid particles to create a barrier that is substantiallyimpermeable to fluids, such as water, oil, and/or gas. Another potentialadvantage of the expandable coating is that expansion of the expandableparticles may be used to change the rheology profile of a fluid in whichthe solid particles are included. Another potential advantage of themethods and compositions of the present invention may be that thisexpansion of the coating in response to fluids may be controlled by atrigger. For example, a chemical trigger such as changing salinity orincorporation of divalent ions may be used to control the expansion ofthe coating. In some instances, the trigger may be a thermal or pressuretrigger such that the expansion of the coating may be controlled bytemperature or pressure. Yet another potential advantage may be that theexpansion of the coating may be reversible. For example, the trigger maybe used to collapse the coating and allow the solid particles to beremoved from the subterranean formation. A particular benefit toremoving the solid particles from the formation may be where the solidparticles were used to create a barrier in a portion of the subterraneanformation through which it is later to desired to produce hydrocarbons.

In accordance with present embodiments, a solid particle may be coatedwith an expandable coating. As used herein, the terms “coat,” “coating,”“coated,” and the like are not intended to imply the extent of coverageof the expandable coating on the solid particle, but rather are intendedto refer to the expandable coating being disposed on an exterior surfaceof the solid particle. FIG. 1 illustrates a solid particle 2 having anexterior surface 4. As illustrated, there is no expandable coating onthe solid particle 2. FIG. 2 illustrates a coated particle 6 thatcomprises a solid particle 2 and an expandable coating 8 disposed on theexterior surface 4 of the solid particle 2. FIG. 2 illustrates theexpandable coating 8 in a collapsed or unexpanded configuration. Inaccordance with present embodiments, the expandable coating 8 may beexpanded, thus increasing the volume of the coated particle 6. In someembodiments, the expandable coating 8 may absorb a fluid to expand andincrease in volume. FIG. 3 illustrates the coated solid particle 6having the expandable coating in an expanded configuration.

The solid particle may include any of a variety of different solidparticles that can be utilized in subterranean treatments, includingweighting agents and lost circulation materials, for example. Lostcirculation materials are typically solid particles that can be includedin subterranean treatment fluids, such as drilling fluids and cementcompositions, among others, to reduce and potentially even prevent theloss of fluid circulation into the formation. Examples of lostcirculation materials that may be used include ground peanut shells,mica, cellophane, ground walnut shells, calcium carbonate, plant fibers,cottonseed hulls, ground rubber, polymeric materials, petroleum coke,graphitic carbon, and combinations thereof. Weighting agents aretypically solid particles that weigh more than water and may be used toincrease the density of the fluid into which the weighting agents areincorporated. By way of example, weighting agents may have a specificgravity of about 2 or greater (e.g., about 3 or greater, about 4 orgreater, etc.). In particular embodiments, the weight agent may have aspecific gravity of about 2.2 or greater. Weighting agents may beselected as the solid particle where it is desired for the coatedparticle to have a dual function, in that the coated particle may beused to modify the density of a treatment as well as controlling fluidflow. Examples of weighting agents that may be used include, but are notlimited to, hematite, hausmannite, barite, sand (e.g., silica flour),cement, Illmanite, calcium carbonate, manganese oxides (e.g., manganesetetraoxide), and combinations thereof. Specific examples of suitableweighting agents include MICROMAX® weight additives, HI-DENSE® weightingagent, and SSA-1™ cement additive, all available from Halliburton EnergyServices, Inc.

The solid particles may have a variety of different physical shapes,including the physical shape of platelets, shavings, fibers, flakes,ribbons, rods, strips, spheroids, toxoids, pellets, tablets, or anyother suitable shape. In some embodiments, the solid particles may havea d50 in a range of from about 1 micron to about 2500 microns. Inalternative embodiments, the solid particles may have a d50 in a rangeof from about 3 microns to about 1200 microns. However, particle sizedistributions outside these defined ranges may also be suitable forparticular applications.

The expandable coating may include any of a variety of differentmaterials that may expand to effect an increase in volume for the coatedparticles. In some embodiments, the expandable coating may comprise aswellable material that swells from an unexpanded configuration to anexpanded configuration when contacted by an actuating fluid. By way ofexample, the swellable material may swell from the unexpanded to theexpanded configuration when it comes into contact with or absorbs theactuating fluid. Examples of suitable actuating fluids include water,such as freshwater, saltwater, and the like, and oils, such as crudeoil, diesel oil, kerosene and the like. In some embodiments, theactuating fluid may be naturally present in the formation such that theswellable material contacts it after placement into the formation. Inalternative embodiments, the actuating fluid may be a carrier fluid usedto place the swellable material in the formation. In furtherembodiments, the coated particle may be pre-expanded such that thecoated particle contacts the actuating fluid prior to incorporation intoa treatment fluid.

In some embodiments, the expandable coating may comprise a material thatswells when it comes into contact with or absorbs water. Examples ofsuitable water-swellable materials include water-swellable polymers,such as those commonly referred to as “superabsorbent polymers.”Superabsorbent polymers are characterized by their ability to absorb upto 500 times or even more their own weight in water. Those of ordinaryskill in the art will appreciate that the absorption and, thus, swellingof superabsorbent polymers may be highly impacted by salinity. Forexample, the presence of valence cations can greatly impact theabsorption capabilities of some superabsorbent polymers. In someembodiments, the superabsorbent polymers may be classified as ahydrogel. Examples of suitable superabsorbent polymers may includepolyacrylates (e.g., polymethacrylate), polyacrylamide,starch-polyacrylate acid graft copolymers, polyethylene oxide polymers,carboxymethyl cellulose type polymers, poly(acrylic acid) and saltsthereof, poly(acrylic-co-acrylamide), graft-poly(ethylene oxide) ofpoly(acrylic acid), poly(2-hydroxyethyl methacrylate),poly(2-hydroxypropyl methacrylate), polyvinyl alcohol cyclic acidanhydride graft copolymer, isobutylene maleic anhydride copolymer,vinylacetate-acrylate copolymer, and starch-polyacrylonitrile graftcopolymers. Combinations of suitable superabsorbent polymers may also besuitable. Other water-swellable materials that behave in a similarfashion with respect to water may also be suitable. For example, astarch or mixture of starches may be used including wheat starch, cornstarch, maize starch, waxy maize starch, potato starch, tapioca starch,and the like. In some embodiments, the starch may be a modified starch.An additional example of a material that may be water swellable includeshydrophobically modified polymers. As used herein, the term“hydrophobically modified” refers to the incorporation into thehydrophilic polymer structure of hydrophobic groups, wherein the alkylchain length is from about 4 to about 22 carbons. Specifically examplesof hydrophilic polymers that may be modified include homo-, co-, orterpolymers such as, but not limited to, polyacrylamides,polyvinylamines, poly(vinylamines/vinyl alcohols), and alkyl acrylatepolymers in general. Additional examples of alkyl acrylate polymersinclude, but are not limited to, polydimethylaminoethyl methacrylate,polydimethylaminopropyl methacrylamide,poly(acrylamide/dimethylaminoethyl methacrylate), poly(methacrylicacid/dimethylaminoethyl methacrylate), poly(2-acrylamido-2-methylpropane sulfonic acid/dimethylaminoethyl methacrylate),poly(acrylamide/dimethylaminopropyl methacrylamide), poly (acrylicacid/dimethylaminopropyl methacrylamide), and poly(methacrylicacid/dimethylaminopropyl methacrylamide). Examples of suitablehydrophobically modified polymers are described in more detail in U.S.Pat. No. 7,117,942, the disclosure of which is incorporated herein byreference. Those of ordinary skill in the art, with the benefit of thisdisclosure, will be able to select an appropriate water-swellablematerial for use in embodiments of the present invention based on avariety of factors, including the application in which the compositionwill be used and the desired swelling characteristics.

In some embodiments, the expandable coating may comprise a material thatswells when it comes into contact with or absorbs oil. Oil-swellablematerials that should be used in embodiments of the weighted elastomerinclude any of a variety of materials that swell upon contact with oil.Some specific examples of suitable oil-swellable materials includeswellable elastomers, such as natural rubber, polyurethane rubber,nitrile rubber, hydrogenated nitrile rubber, acrylate butadiene rubber,polyacrylate rubber, butyl rubber, brominated butyl rubber, chlorinatedbutyl rubber, chlorinated polyethylene rubber, isoprene rubber,chloroprene rubber, neoprene rubber, butadiene rubber, styrene butadienecopolymer rubber, sulphonated polyethylene, ethylene acrylate rubber,epichlorohydrin ethylene oxide copolymer rubber,ethylene-propylene-copolymer (peroxide cross-linked),ethylene-propylene-copolymer (sulphur cross-linked),ethylene-propylene-diene terpolymer rubber, ethylene vinyl acetatecopolymer, fluoro rubbers, fluoro silicone rubbers, silicone rubbers,poly 2,2,1-bicyclo heptene (polynorborneane), alkylstyrene, andcrosslinked substituted vinyl acrylate copolymers. Combinations ofsuitable swellable elastomers may also be used. Other oil-swellablematerials that behave in a similar fashion with respect to oil also maybe suitable. Those of ordinary skill in the art, with the benefit ofthis disclosure, will be able to select an appropriate oil-swellablematerial for use in embodiments of the present invention based on avariety of factors, including the application in which the compositionwill be used and the desired swelling characteristics.

Embodiments of the swellable materials may be dual oil/water swellable,in that the swellable material may comprise a combination or mixture ofboth oil-swellable and water-swellable materials. A swellable materialis characterized as “dual oil/water-swellable” when it swells uponcontact with or absorption of both oil and water.

The expandable coating may be applied to the surface of the solidparticles using any suitable technique. The coating process may be acontinuous or batch process. Examples of suitable techniques for coatingthe solid particles include spray drying, fluidized-bed coating, andbatch mixing. The amount of the expandable coating used in embodimentsmay depend on a number of factors, including the particular expandablecoating and the specific end-use application. In certain embodiments,the coated particle may have a weight ratio of the expandable coating tothe solid particle of about 99:1 to about 0.1:1 and, alternatively, aweight ratio of about 3:1 to about 0.5:1. While the expandable coatingmay be attached to the outer surface of the solid particles, theexpandable coating does not necessarily coat the entire outer surface.In other words, at least a portion of the surface of the solid particlesmay remain uncovered in certain embodiment even after coating with theexpandable coating. In certain embodiments, at least about 1% (e.g.,about 1%, about 5%, about 10% or more) of the surface of the solidparticles may be uncovered.

Swellable materials suitable for use in embodiments of the presentinvention may generally swell by up to about 500% of their original sizewhen contacted by the actuating fluid. For example, the swelling may beat least 10%, at least about 50%, or at least about 100%. Under downholeconditions, this swelling may be more or less depending on theconditions presented. In some embodiments, the swelling may be up toabout 200% under downhole conditions. However, as those of ordinaryskill in the art, with the benefit of this disclosure, will appreciate,the actual swelling of the swellable material may vary, for example,based on the amount of the swellable material used, temperature,pressure, salinity, and divalent ion concentration, among other factors.

According to present embodiments, a trigger may be used toactivate/de-activate the swelling of the swellable materials. Forexample, the trigger may activate the swelling of the swellablematerials such that the swellable materials may swell from theunexpanded to the expanded configuration when they come into contactwith or absorb the actuating fluid. By way of further example, thetrigger may alternatively be used to de-activate the swelling such thatthe swellable material may desorb some or even all the actuating fluidand, thus, decrease in volume. In some embodiments, the trigger maychange the rate of swelling, for example, increasing or decreasing therate of which the swellable material absorbs the actuating fluid. Insome instances, the trigger may be a thermal or pressure trigger suchthat the expansion of the coating may be controlled by temperature orpressure. In alternative embodiments, the trigger may be a chemicaltrigger—such as changing salinity or incorporation of divalent ions—maybe used to control the expansion of the coating.

In some embodiments, a thermal trigger may be used toactivate/de-activate the swelling of the swellable materials. In someembodiments, when the swellable material is exposed to an appreciablyhigh temperature, the swelling may be triggered such that the swellablematerials may swell from the unexpanded to the expanded configurationwhen it comes into contact with or absorbs the actuating fluid. It isbelieved that in some embodiments in which the subterranean temperatureis at least 100° C. or higher, the swelling of the materials may beactivated. It is further believed that higher temperatures, in someembodiments, may cause the swelling to occur more quickly, e.g., theswelling more occur more quickly at a temperature of 120° C. than at atemperature of 100° C. In alternative embodiments, when the swellablematerial is exposed to an appreciably high temperature, the swelling maybe de-activated such that the swellable materials may desorb some oreven all the actuating fluid causing the swellable material to decreasein volume.

In some embodiments, a pressure trigger may be used toactivate/de-activate the swelling of the swellable materials. In someembodiments, when the swellable material is exposed to an appreciablyhigh pressure, the swelling may be triggered such that the swellablematerials may swell from the unexpanded to the expanded configurationwhen it comes into contact with or absorbs the actuating fluid. Inalternative embodiments, when the swellable material is exposed to anappreciably high pressure, the swelling may be de-activated such thatthe swellable materials may desorb some or even all the actuating fluidcausing the swellable material to decrease in volume. The pressuretrigger, in some embodiments, may be the subterranean formation pressureor a shut-in pressure.

In some embodiments, a chemical trigger may be used toactivate/de-activate the swelling of the swellable materials. Thechemical trigger may include salinity and/or divalent ion concentration,among others. In some embodiments, a fluid comprising a dissolvent saltand/or divalent ions may be used to control swelling. For example,swelling of certain swellable materials may be de-activated byincreasing salinity and/or incorporation of divalent ions, such ascalcium ions. In certain embodiments, the swelling of the swellablematerial may be de-activated in a fluid having a salinity of 0.5% suchthat the absorbency of the swellable may drop by 50% or more. Forexample, polyacrylamide can absorb up to 500 times its volume in freshwater, but at 0.9% salinity (NaCl), it absorbency can drop to 50%. Inaddition, a small amount of calcium chloride could shut off swelling.Accordingly, salinity and/or calcium ions may be used to control theexpansion of the swellable material. In some embodiments, salinityand/or calcium ions may also be used to regulate the rate of swelling.For example, at a given temperature, a swellable material in a fluidhaving a certain salinity and/or calcium ion concentration may reach anexpanded configuration more slowly than when the fluid has a reducedsalinity and/or calcium ion concentration.

In accordance with embodiments of the present invention, the coatedparticles may be incorporated into a treatment fluid. As used herein,the term “treatment fluid” refers to any fluid that may be used inconjunction with a desired function and/or for a desired purpose. Theterm “treatment fluid” does not imply any particular action by the fluidor any component thereof. Similarly, the term “treatment” or “treating,”as used herein, refers to any subterranean operation performed inconjunction with a desired function and/or for a desired purpose. Theterm “treatment” does not imply any particular action. In someembodiments, the coated particles may be introduced into the treatmentfluid directly prior to be introduced into a subterranean formation inan “on-the-fly treatment.” In an on-the-fly treatment, a flowing streamis continuously introduced into another flowing stream so that thestreams are combined and mixed while continuing to flow as a singlestream as part of an on-going treatment. For example, the coatedparticles may be mixed with a treatment fluid on the fly as thetreatment fluid is being delivered to the subterranean formation. Suchmixing may also be described as “real-time” mixing. As will beunderstood by those of ordinary skill, the coated particles may also beincorporated into a treatment fluid using other mixing techniques, suchas batch or partial batch mixing, for example.

Generally, any treatment fluid suitable for subterranean operations maybe used in accordance with embodiments, including aqueous gels,viscoelastic surfactant gels, foamed gels, and emulsions, among others.Embodiments of the treatment fluid may be non-settable, in that thetreatment fluid does not set and harden to develop compressive strength.Examples of suitable aqueous gels may comprise an aqueous liquid and oneor more gelling agents. In some embodiments, the aqueous gel may furthercomprise a crosslinking agent for crosslinking the gel and furtherincreasing the viscosity of the fluid. Examples of suitable emulsionsmay comprise two immiscible liquids such as an aqueous liquid or gelledliquid and a hydrocarbon. Foams may be created by incorporation of agas, such as carbon dioxide or nitrogen. In some embodiments, thetreatment fluids may comprise an aqueous-based fluid, which may includefreshwater, saltwater (e.g., water containing one or more saltsdissolved therein), seawater, or any other suitable aqueous liquid. Thedensity of the water can be increased to provide additional particletransport and/or suspension capabilities. In some embodiments, thetreatment fluid may comprise a non-aqueous base fluid. Suitablenon-aqueous base fluids may include one or more organic liquids, such ashydrocarbons (e.g., paraffins, kerosene, xylene, toluene, or diesel),oils (e.g., mineral oils or synthetic oils), esters, and the like.

The amount of the coated particles to include in the treatment fluids isdependent on a variety of factors, including, but not limited to, theapplication in which the treatment fluid is to be utilized. In someembodiments, the coated particles should be present in the treatmentfluids in an amount in the range of from about 0.01% to about 50% byweight of the treatment fluid. In other embodiments, the coated particleshould be present in the treatment fluids in an amount in the range offrom about 0.5% to about 20% by weight of the treatment fluid and,alternatively, from about 1% to about 10% by weight of the treatmentfluid. While these ranges may be suitable in certain embodiments, anyamount within the disclosed range may also be suitable. Those ofordinary skill in the art, with the benefit of this disclosure, will beable to select an appropriate amount of the coated particles to includein the treatment fluids of the present invention based on a variety offactors, including the application in which the fluid will be used,compatibility with other treatment fluids, and the desired swellingcharacteristics.

Additional additives may be added to the treatment fluids as deemedappropriate for a particular application by one skilled in the art withthe benefit of this disclosure. Examples of such additives include, butare not limited to, weighting agents, surfactants, scale inhibitors,antifoaming agents, bactericides, salts, foaming agents, acids, fluidloss control additives, viscosifying agents, cross linking agents, gelbreakers, shale swelling inhibitors, combinations thereof, and the like.

In certain embodiments, the treatment fluid may be a drilling fluid, afracturing fluid, a work over fluid, a well bore cleanup fluid, a gravelpacking fluid, a cement composition, or any other suitable fluids usedin subterranean treatments. In another embodiment, the treatment fluidmay be a “spot treatment” or “pill,” wherein the treatment is pumpedinto the well bore to place the coated particles in a specific portionof the well bore.

Embodiments of the methods of the present invention may be employed in anumber of subterranean applications. For example, the coated particlesmay be used, inter alia, as a lost circulation treatment or aconformance material to prevent undesired water production. In someembodiments, a method may comprise: placing coated particles into apermeable zone of a subterranean formation, the coated particlescomprising solid particles coated with an expandable coating; andallowing the coated particles to form a barrier to fluid flow in thepermeable zone. The permeable zone may comprise or include fracturesand/or the pore matrix of the subterranean formation. The subterraneanformation may be penetrated by a well bore. The expandable coating maybe pre-expanded, allowed to expand in the treatment fluid duringplacement in the permeable zone, or allowed to expand after placement inthe permeable zone. In addition, any of the aforementioned triggers(e.g., thermal trigger, pressure trigger, chemical trigger, etc.) may beused to activate/de-activate swelling of the coated particles. Accordingto some embodiments in which the coated particles are used, the coatedparticles may form a particle pack in the permeable zone that acts asubstantially impermeable barrier to fluid and/or gas flow through thepermeable zone of the subterranean formation.

In some embodiments, the methods of the present invention may compriseincluding coated particles in a treatment fluid, the coated particlescomprising solid particles coated with an expandable coating that ispre-expanded; and introducing the treatment fluid into a permeable zoneof a subterranean formation. The coated particles may be allowed to forma barrier to fluid flow in the permeable zone. Embodiments of thepresent invention contemplate that the expandable coating on the solidparticles may be pre-expanded prior to formulation of the treatmentfluid. In these embodiments, the expandable coating may be exposed to anactuating fluid (e.g., water, oil) prior to inclusion of the coatedparticles in the treatment fluid such that the expandable coating atleast partially expands prior to placement into the treatment fluid. Theexpandable coating may undergo further expansion in the treatment fluidand/or after placement into the subterranean formation. Alternative, theexpandable coating may be deactivated causing some or even all theactuating fluid to desorb such that the volume of the coated particlemay be reduced for removal of the barrier in the subterranean formation.

In some embodiments, the methods of the present invention may compriseproving a treatment fluid comprising an actuating fluid and coatedparticles, the coated particles comprising solid particles coated withan expandable coating; and introducing the treatment fluid into apermeable zone of a subterranean formation. The coated particles may beallowed to form a barrier to fluid flow in the permeable zone.Embodiments of the present invention contemplate that the expandablecoating on the solid particles may at least partially expand due tointeraction with an actuating fluid that may be present in the treatmentfluid. This swelling may occur, for example, while the treatment fluidis being introduced into the subterranean formation. In someembodiments, a chemical trigger may be used to reduce or prevent theswelling of the expandable coating in the treatment fluid. For example,the treatment fluid may be formulated to have a salinity and/or divalention concentration that reduces and/or prevents the swelling of theexpandable coating due to interaction with an actuating fluid that maybe present in the treatment fluid. The expandable coating may thenexpand or undergo further expansion due to contact with actuatingfluid(s) after placement in the subterranean formation.

In some embodiments, the methods of the present invention may compriseproving a treatment fluid comprising coated particles, the coatedparticles comprising solid particles coated with an expandable coating;and introducing the treatment fluid into a permeable zone of asubterranean formation. The coated particles may be allowed to form abarrier to fluid flow in the permeable zone. Embodiments of the presentinvention contemplate that the expandable coating on the solid particlesmay at least partially expand due to interaction with an actuating fluidencountered after coated particles have been introduced into thesubterranean formation. For example, an actuating fluid may come intocontact with the barrier formed by the coated particles causing theexpandable coating on the solid particles to swell, which may furtherdecrease the permeability of the barrier to fluid flow. The actuatingfluid may be introduced into the subterranean formation via the wellbore or may be a formation fluid.

In some embodiments, the methods may comprise shutting in the well borefor some period of time after the treatment fluid has been introduced.The well bore may be shut in for a number of reasons, including allowingthe coated particles to undergo a desired level of expansion. Inaddition, the well bore may also be shut in to provide a shut-inpressure that activates/de-activates swelling of the coated particles.In some embodiments, the shut-in time may comprise a period of time fromabout one hour to about one month or even longer. In some embodiments,the shut-in tome may comprise a period of time from about three hours toabout fifteen hours.

In some embodiments, methods of using the coated particles in alost-circulation treatment may comprise: providing a treatment fluidcomprising coated particles, the coated particles comprising solidparticles coated with an expandable coating; introducing the treatmentfluid into a lost-circulation zone of a subterranean formation such thatthe coated particles form a barrier to fluid flow in thelost-circulation zone. For example, the treatment fluid may beintroduced into a well bore penetrating the subterranean formation andallowed to circulate through the well bore at least to the zone whereloss of fluid circulation is believed to be occurring. Thelost-circulation zone may comprise or include fractures and/or the porematrix of the subterranean formation. The expandable coating may bepre-expanded, allowed to expand in the treatment fluid during placementin the permeable zone, and/or allowed to expand after placement in thelost-circulation zone. In addition, any of the aforementioned triggers(e.g., thermal trigger, pressure trigger, chemical trigger, etc.) may beused to activate/de-activate swelling of the coated particles in thelost-circulation treatment. According to some embodiments in which thecoated particles are used, the coated particles may form a particle packin the lost-circulation zone that acts as a substantially impermeablebarrier to fluid and/or gas flow through the lost-circulation zone ofthe subterranean formation. The particle pack may be formed, forexample, by packing off perforation tunnels, plating off a formationsurface, plating off a hole behind a slotting liner, or packing alongthe surface of a hydraulic fracture. In certain embodiments, the barrierformed by the solid particles may reduce and/or eliminate the loss ofdrilling fluids and/or other treatment fluids into the lost-circulationzone.

In example embodiments of a lost-circulation treatment, the treatmentmay comprise including coated particles in a drilling fluid, the coatedparticles comprising solid particles coated with an expandable coating;using a drill bit to enlarge a well bore penetrating a subterraneanformation; and circulating the drilling fluid past the drill bit. Insome embodiments, the drilling fluid can be allowed to circulate in thewell bore such that the coated particles form a barrier to fluid flow ina lost-circulation zone in the subterranean formation.

In some embodiments, methods of using the coated particles in aconformance treatment may comprise: providing a treatment fluidcomprising coated particles, the coated particles comprising solidparticles coated with an expandable coating; introducing the treatmentfluid into a permeable zone of a subterranean formation such that thecoated particles form a barrier to fluid flow in the permeable zone. Thepermeable zone may comprise or include fractures and/or the pore matrixof the subterranean formation. The subterranean formation may bepenetrated by a well bore. The expandable coating may be pre-expanded,allowed to expand in the treatment fluid during placement in thepermeable zone, and/or allowed to expand after placement in thepermeable zone. In addition, any of the aforementioned triggers (e.g.,thermal trigger, pressure trigger, chemical trigger, etc.) may be usedto activate/de-activate swelling of the coated particles in theconformance treatment. According to some embodiments in which the coatedparticles are used, the coated particles may form a particle pack in thepermeable zone that acts a substantially impermeable barrier to fluidand/or gas flow through the permeable zone of the subterraneanformation. In certain embodiment, the fluid that is blocked may be waterfrom water-flooding operations, e.g., water that has been introducedinto the subterranean formation from neighboring wells during secondaryrecovery operations. In some embodiments, the barrier formed by thecoated particles may prevent the influx of water into the well bore,improving the water-to-hydrocarbon ratio in the hydrocarbons that areproduced through the well bore. The water can be the result of awater-producing zones communicating with the hydrocarbon-producingformations or zones by fractures, high-permeability streaks, and thelike. Alternatively, the water can be caused by a variety of otheroccurrences which are well known in the art, including water coning,water cresting, bottom water, channeling at the well bore, etc.

In some embodiments, the barrier formed by the solid particles in thepermeable zone of the subterranean formation may be removed. Embodimentsof the present invention may further comprise removing the barrierformed by the solid particles from the subterranean formation such thatpermeability of the permeable zone may be at least partially restored.In some embodiments, the permeable zone may be restored to itspre-treatment permeability. Restoration of permeable may be desired, forexample, to allow the maximum flow of produced fluids from the permeablezone into the well bore. De-activation of the swelling of the expandablecoating may be used, for example, to decrease volume of the coatedparticles in the barrier to facilitate removal. Any of theaforementioned triggers (e.g., thermal trigger, pressure trigger,chemical trigger, etc.) may be used to de-activate swelling of thecoated particles for removal. By way of example, the barrier may becontacted by a fluid having a salinity and/or divalent ion concentrationthat causes the expandable coating to desorb the actuating fluid and,thereby, decrease in volume. In some embodiments, the fluid may effectthe decrease in volume and/or remove the coating from the solidparticles and then carry the coated particles or resultant solidparticles out of the well bore. In alternative embodiments, a pressureand/or thermal trigger may be used to cause the expandable coating tode-activate and, thus, desorb the actuating fluid to decrease in volume.The coated particles after the decrease in volume may then be displacedfrom the subterranean formation, for example, by circulating apost-flush fluid through the well bore to come into contact with thecoated particles and carry them back out of the well bore.

In some embodiments, the coated particles may be used to reduce fluidloss from a treatment fluid introduced into a subterranean formation.The subterranean formation may be penetrated by a well bore with thetreatment fluid introduced into the well bore. It is believed that thecoated particles may act to reduce fluid loss by blocking pore throatsor flow channels in the subterranean formation. A solid particle with anexpandable coating may be used to block larger pore throats or otherflow channels than just the solid particles alone. In addition, withoutbeing limited by theory, if a filter cake is formed that comprises thesolid particles and then the expandable coating is allowed to expand,the expansion could fill in gaps between the solid particles that wouldotherwise allow leakage of the treatment fluid if just the solidparticles alone were used. In some embodiments, coated particles may beused to reduce fluid loss from a drilling fluid. The expandable coatingmay be pre-expanded, allowed to expand in the treatment fluid duringplacement in the permeable zone, or allowed to expand after placement inthe permeable zone. In addition, any of the aforementioned triggers(e.g., thermal trigger, pressure trigger, chemical trigger, etc.) may beused to activate/de-activate swelling of the coated particles.

In some embodiments, the coated particles may be used to modify therheology profile of a treatment fluid, such as a drilling fluid. Forexample, expansion of the expandable coating to increase in volumeshould increase the viscosity of a treatment fluid in which the coatedparticles are included. Expansion of the coating and resulting viscosityincrease may be beneficial in a number of applications where low shearrheology and increased fluid carrying capacity are desired, such as inpacker applications, among others. In packer applications, for example,the increased viscosity would aid in keeping weighting materials inplace and thermal induced currents minimized. By way of further example,reduction in volume of the expandable coating should decrease the volumeof a treatment fluid in which the coated particles are included. Areduction in viscosity may be beneficial in a number of applicationssuch as well bore cleanup or prior to cementing to reduce the equivalentcirculating density of the fluid and improve zonal isolation.

It should be understood that the compositions and methods are describedin terms of “comprising,” “containing,” or “including” variouscomponents or steps, the compositions and methods can also “consistessentially of” or “consist of” the various components and steps.Moreover, the indefinite articles “a” or “an,” as used in the claims,are defined herein to mean one or more than one of the element that itintroduces.

For the sake of brevity, only certain ranges are explicitly disclosedherein. However, ranges from any lower limit may be combined with anyupper limit to recite a range not explicitly recited, as well as, rangesfrom any lower limit may be combined with any other lower limit torecite a range not explicitly recited, in the same way, ranges from anyupper limit may be combined with any other upper limit to recite a rangenot explicitly recited. Additionally, whenever a numerical range with alower limit and an upper limit is disclosed, any number and any includedrange falling within the range are specifically disclosed. Inparticular, every range of values (of the form, “from about a to aboutb,” or, equivalently, “from approximately a to b,” or, equivalently,“from approximately a-b”) disclosed herein is to be understood to setforth every number and range encompassed within the broader range ofvalues even if not explicitly recited. Thus, every point or individualvalue may serve as its own lower or upper limit combined with any otherpoint or individual value or any other lower or upper limit, to recite arange not explicitly recited.

Therefore, the present invention is well adapted to attain the ends andadvantages mentioned as well as those that are inherent therein. Theparticular embodiments disclosed above are illustrative only, as thepresent invention may be modified and practiced in different butequivalent manners apparent to those skilled in the art having thebenefit of the teachings herein. Although individual embodiments arediscussed, the invention covers all combinations of all thoseembodiments. Furthermore, no limitations are intended to the details ofconstruction or design herein shown, other than as described in theclaims below. Also, the terms in the claims have their plain, ordinarymeaning unless otherwise explicitly and clearly defined by the patentee.It is therefore evident that the particular illustrative embodimentsdisclosed above may be altered or modified and all such variations areconsidered within the scope and spirit of the present invention. Ifthere is any conflict in the usages of a word or term in thisspecification and one or more patent(s) or other documents that may beincorporated herein by reference, the definitions that are consistentwith this specification should be adopted.

What is claimed is:
 1. A method of drilling a well bore comprising:including coated particles in a drilling fluid, the coated particlescomprising solid particles coated with an expandable coating; using adrill bit to enlarge the well bore; circulating the drilling fluid pastthe drill bit; and allowing the expandable coating to expand, wherein anexpansion of the expandable coating is controlled by divalent ions. 2.The method of claim 1 wherein the solid particles comprise a lostcirculation material selected from the group consisting of a groundpeanut shell, mica, cellophane, ground walnut shell, calcium carbonate,plant fiber, a cottonseed hull, ground rubber, polymeric material,petroleum coke, graphitic carbon, and any combination thereof.
 3. Themethod of claim 1 wherein the solid particles comprise a weighting agentselected from the group consisting of hematite, hausmannite, barite,sand, silica flour, cement, Illmanite, calcium carbonate, manganeseoxide, manganese tetraoxide, and any combination thereof.
 4. The methodof claim 1 wherein the expandable coating comprises a water-swellablematerial.
 5. The method of claim 1 wherein the expandable coatingcomprise a hydrogel.
 6. The method of claim 1 wherein the expandablecoating comprises a polymer selected from the group consisting of apolyacrylate, a polymethacrylate, polyacrylamide, a starch-polyacrylateacid graft copolymer, a polyethylene oxide polymer, a carboxymethylcellulose polymers, poly(acrylic acid) and salts thereof,poly(acrylic-co-acrylamide), graft-poly(ethylene oxide) of poly(acrylicacid), poly(2-hydroxyethyl methacrylate), poly(2-hydroxypropylmethacrylate), polyvinyl alcohol cyclic acid anhydride graft copolymer,isobutylene maleic anhydride copolymer, vinylacetate-acrylate copolymer,a starch-polyacrylonitrile graft copolymers, a starch, a modifiedstarch, a hydrophobically modified polymer, and any combination thereof.7. The method of claim 1 wherein the expandable coating comprises anoil-swellable material.
 8. The method of claim 1 wherein the expandablecoating comprise an oil-swellable material selected from the groupconsisting of natural rubber, polyurethane rubber, nitrile rubber,hydrogenated nitrile rubber, acrylate butadiene rubber, polyacrylaterubber, butyl rubber, brominated butyl rubber, chlorinated butyl rubber,chlorinated polyethylene rubber, isoprene rubber, chloroprene rubber,neoprene rubber, butadiene rubber, styrene butadiene copolymer rubber,sulphonated polyethylene, ethylene acrylate rubber, epichlorohydrinethylene oxide copolymer rubber, ethylene-propylene-copolymer (peroxidecross-linked), ethylene-propylene-copolymer (sulphur cross-linked),ethylene-propylene-diene terpolymer rubber, ethylene vinyl acetatecopolymer, a fluoro rubber, a fluoro silicone rubber, a silicone rubber,poly 2,2,1-bicyclo heptene (polynorborneane), alkylstyrene, acrosslinked substituted vinyl acrylate copolymer, any combinationthereof.
 9. The method of claim 1 wherein the coated particles areintroduced into a permeable zone of the subterranean formation such thatthe coated particles form a barrier to fluid flow in the permeable zone.10. The method of claim 9 wherein the permeable zone is a lostcirculation zone, the coated particles preventing loss of other fluidsinto the permeable zone from a well bore penetrating the subterraneanformation, wherein the well bore penetrates the subterranean formation.11. The method of claim 9 wherein the coated particles block flow ofwater from the permeable zone into a well bore, wherein the well borepenetrates the subterranean formation.
 12. The method of claim 9 furthercomprising removing the barrier to fluid flow formed by the coatedparticles, the removing comprising decreasing volume of the coatedparticles in the barrier to facilitate removal.
 13. The method of claim9 further comprising removing the barrier to fluid flow formed by thecoated particles, the removing comprising contacting the coatedparticles with a fluid comprising a chemical trigger to de-activateswelling of the coated particles, wherein the chemical trigger isselected from the group consisting of a dissolved salt, a divalent ion,and combinations thereof.
 14. The method of claim 1 wherein theexpandable coating expands in volume in a treatment fluid used inintroducing the coated particles into the subterranean formation. 15.The method of claim 1 wherein the coated particles are provided with theexpandable coating in an expanded configuration.
 16. The method of claim1 further comprising contacting the coated particle with an actuatingfluid to facilitate the expansion of the expandable coating.
 17. Themethod of claim 16 wherein the actuation fluid comprises a formationfluid.
 18. The method of claim 1 wherein the coated particles expand orcontract in volume in the drilling fluid to change the rheology profileof the drilling fluid.
 19. A method of drilling a well bore in asubterranean formation comprising: including coated particles in adrilling fluid, the coated particles comprising solid particles coatedwith an expandable coating, the drilling fluid comprising divalent ionsto control swelling of the expandable coating; using a drill bit toenlarge the well bore; circulating the drilling fluid past the drillbit; allowing at least a portion of the coated particles to form aparticle pack in the subterranean formation, wherein the coatedparticles are pre-expanded, expand during placement in the subterraneanformation, and/or expand after placement in the subterranean formationto form a barrier to fluid flow; and contacting the coated particleswith a fluid having a divalent ion concentration that causes theexpandable coating to decrease in volume.
 20. The method of claim 19,further comprising contacting the coated particles in the particle withan actuating fluid to cause the expandable coating to expand.